Foaming agent for subterranean formations treatment, and methods of use thereof

ABSTRACT

A wellbore treatment fluid is formed from an aqueous medium, a gas component, a viscosifying agent, and a surfactant. The surfactant is represented by the chemical formula: 
       [R—(OCH 2 CH 2 ) m —O q —YO n ] p X
 
     wherein R is a linear alkyl, branched alkyl, alkyl cycloaliphatic, or alkyl aryl group; O is an oxygen atom; Y is either a sulfur or phosphorus atom; m is 1 or more; n is a integer ranging from 1 to 3; p is a integer ranging from 1 to 4; q is a integer ranging from 0 to 1; and X is a cation. The fluid may be used in treating a subterranean formation penetrating by a wellbore by introducing the fluid into the wellbore. The fluid may be used in fracturing a subterranean formation penetrated by a wellbore by introducing the fluid into the formation at a pressure equal to or greater than the fracture initiation pressure.

This application claims the benefit of U.S. Provisional PatentApplication No. 60/827,324, filed Sep. 28, 2006, which is incorporatedherein by reference in its entirety.

BACKGROUND OF THE INVENTION

This invention relates to fluids used in treating a subterraneanformation. In particular, the invention relates to aqueous energizedwellbore treatment fluids, and methods of forming and using such fluids.

Various types of fluids are used in operations related to thedevelopment and completion of wells that penetrate subterraneanformations, and to the production of gaseous and liquid hydrocarbonsfrom natural reservoirs into such wells. These operations includeperforating subterranean formations, fracturing subterranean formations,modifying the permeability of subterranean formations, or controllingthe production of sand or water from subterranean formations. The fluidsemployed in these oilfield operations are known as drilling fluids,completion fluids, work-over fluids, packer fluids, fracturing fluids,stimulation fluids, conformance or permeability control fluids,consolidation fluids, and the like.

Fluid technologies incorporating a gaseous component or a supercriticalfluid to form a foam or energized fluid are commonly used in thestimulation of oil and gas wells. For example, some viscoelastic fluidsused as fracturing fluids contain a gas such as air, nitrogen or carbondioxide to provide an energized fluid or foam. Such fluids are commonlyformed by injecting an aqueous solution (“base fluid”) concomitantlywith a gas, most commonly nitrogen, carbon dioxide or their mixtures,into the formation. Among other benefits, the dispersion of the gas intothe base fluid in the form of bubbles or droplets increases theviscosity of such fluid and impacts positively its performance,particularly its ability to effectively induce hydraulic fracturing ofthe formation, and also its capacity to carry solids (“proppants”) thatare placed within the fractures to create pathways through which oil orgas can be further produced. The presence of the gas also enhances theflowback of the base fluid from the interstices of the formation and ofthe proppant pack into the wellbore, due to the expansion of such gasonce the pressure is reduced at the wellhead at the end of thefracturing operation. Other common uses of foams or energized fluidsinclude wellbore cleanout, gravel packing, acid diversion, fluid losscontrol, and the like.

Foamed and energized fracturing fluids invariably contain “foamers”,most commonly surfactants or blends of surfactants that facilitate thedispersion of the gas into the base fluid in the form of small bubblesor droplets, and confer stability to the dispersion by retarding thecoalescence or recombination of such bubbles or droplets. Foamed andenergized fracturing fluids are generally described by their foamquality, i.e. the ratio of gas volume to the foam volume. If the foamquality is between 52% and 95%, the fluid is conventionally called foam,and below 52%, an energized fluid. However, as used herein the term“energized fluid” is defined as any stable mixture of gas and liquid,notwithstanding the foam quality value.

The ability to formulate stable energized fluids with rheologicalproperties suitable for fracturing operations becomes increasinglydifficult as the temperature of the subterranean formation increases.The matter is worsened when carbon dioxide is present in the gas phase,since carbon dioxide exhibits high solubility in aqueous solutions. Thehigh solubility of carbon dioxide facilitates mass transfer betweenbubbles and accelerates foam-destabilizing mechanisms such as so-calledOstwald ripening, which ultimately lead to phase separation and to theloss of fluid viscosity. Furthermore, carbon dioxide reacts with waterto form carbonic acid. The formation of carbonic acid imposes a low pHenvironment for the fluid (typically in the range 3.5-4), thus impedingthe necessary control of pH for efficient crosslinking with borate ionsand often with other metallic ions. Exposure to low pH and hightemperatures promotes degradation of the polymeric chains, particularlyif polysaccharides are used as viscosifying agents, thus contributing tothe referred loss of foam stability and viscosity.

The need to identify suitable chemicals to formulate viscous foams andenergized fluids containing carbon dioxide, particularly at elevatedtemperatures in excess of about 93° C., and more particularly attemperatures in excess of about 121° C., particularly using CO₂ or N₂,is known to those skilled in the art. Furthermore, there are needs forimproved methods to utilize such formulations in the treatment andfracturing of subterranean formations penetrated by a wellbore.

Due to the relatively high cost associated with the foaming agents,there also exists a need to identify efficient surfactants that generatestable foams at reduced cost. A fluid that can achieve the above wouldbe highly desirable. These needs are met at least in part by thefollowing invention.

SUMMARY OF THE INVENTION

The invention provides a wellbore treatment fluid comprising an aqueousmedium, a gas component, a viscosifying agent, and a surfactant, whereinthe surfactant is represented by the chemical formula:

[R—(OCH₂CH₂)_(m)—O_(q)—YO_(n)]_(p)X

wherein R is a linear alkyl, branched alkyl, alkyl cycloaliphatic, oralkyl aryl group; O is an oxygen atom; Y is either a sulfur orphosphorus atom; m is 1 or more; n is an integer ranging from 1 to 3; pis an integer ranging from 1 to 4; q is an integer ranging from 0 to 1;and X is a cation.

The invention also provides a method of fracturing a subterraneanformation penetrating by a wellbore, including the steps of preparing afluid comprising an aqueous medium, a gas component, a viscosifyingagent, and a surfactant, wherein the surfactant is represented by thechemical formula:

[R—(OCH₂CH₂)_(m)—O_(q)—YO_(n)]_(p)X

wherein R is a linear alkyl, branched alkyl, alkyl cycloaliphatic, oralkyl aryl group; O is an oxygen atom; Y is either a sulfur orphosphorus atom; m is 1 or more; n is a integer ranging from 1 to 3; pis a integer ranging from 1 to 4; q is a integer ranging from 0 to 1;and X is a cation, and introducing the fluid into the formation at apressure equal to or greater than the fracture initiation pressure.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present invention, and theadvantages thereof, reference is now made to the following descriptionstaken in conjunction with the accompanying figures, in which:

FIG. 1 shows the viscosities over time of N₂ foamed guar-based fluids atabout 120° C. containing either Surfactant A (a sodium tridecyl ethersulfate containing surfactant) or Surfactant B (an ammonium C6-C10alcohol ethoxysulfate containing surfactant);

FIG. 2 shows the viscosities over time of CO₂ foamed guar-based fluidsat about 120° C. containing either Surfactant A or Surfactant C (anamphoteric alkyl amine containing surfactant);

FIG. 3 shows the viscosity over time of a N₂ foamed guar-based fluid atabout 120° C. containing Surfactant D (a sodium lauryl sulfatecontaining surfactant);

FIG. 4 shows the viscosity over time of a CO₂ foamed guar-based fluidcontaining Surfactant A at a temperature of about 135° C.;

FIG. 5 shows the viscosity over time of a CO₂ foamed diutan-based fluidcontaining Surfactant A at a temperature of about 150° C.;

FIG. 6 shows the viscosities over time of CO₂ and N₂ foamedcarboxymethyl hydroxypropylguar (CMHPG)-based fluids containingSurfactant A at temperatures of about 120° C.;

FIG. 7 shows the viscosities over time of a N₂ foamed guar-based fluidcontaining Surfactant A at temperatures of about 100° F. (38° C.) and150° F. (66° C.);

FIG. 8 shows the viscosities over time of a N₂ foamed guar-based fluidcontaining Surfactant A at temperatures of about 200° F. (93.3° C.) and250° F. (121° C.);

FIG. 9 shows the viscosities over time of a CO₂ foamed guar-based fluidcontaining Surfactant A at temperatures of about 100° F. (38° C.) and150° F. (66° C.);

FIG. 10 shows the viscosities over time of a CO₂ foamed guar-based fluidcontaining Surfactant A at temperatures of about 200° F. (93.3° C.) and250° F. (121° C.);

FIG. 11 shows the viscosities over time of N₂ foamed CMHPG-based fluidscontaining Surfactant A at temperatures of about 100° F. (38° C.), 150°F. (66° C.) and 200° F. (93.3° C.);

FIG. 12 shows the viscosities over time of CO₂ foamed CMHPG-based fluidscontaining Surfactant A at temperatures of about 150° F. (66° C.) and200° F. (93.3° C.);

FIG. 13 shows the viscosities over time of N₂ foamed CMHPG-based fluidscontaining Surfactant A at a temperature of about 200° F. (93.3° C.),with and without the use of a biocide;

FIG. 14 shows the viscosities over time of CO₂ foamed CMHPG-based fluidscontaining Surfactant A at a temperature of about 200° F. (93.3° C.),with and without the use of a biocide composed of 9 wt %1,2-benzisothiazolin-3-one and 3.5 wt % sodium hydroxide, 43 wt %propane-1,2-diol, in an aqueous solution;

FIG. 15 shows the viscosities over time of CO₂ foamed CMHPG-based fluidscontaining Surfactant A at a temperature of about 200° F. (93.3° C.),with and without the use of a Biocide 1 (composed of 42.5 wt %propane-1,2-diol, 2 to 5 wt % sodium hydroxide, 9 wt %1,2-benziisothiazolin-3-one, and 43.5 to 46.5 wt % water) and Biocide 2(composed of 1 to 5 wt % 2-bromo-3-nitrilopropionamide and 60 to 100 wt% 2,2-dibromo-3-nitrilopropionamine);

FIG. 16 shows the viscosities over time of CO₂ foamed CMHPG-based fluidscontaining Surfactant B at a temperature of about 200° F. (93.3° C.),with and without the use of Biocide 1;

FIG. 17 shows the viscosities over time of CO₂ foamed guar-based fluidscontaining Surfactant A at a temperature of about 200° F. (93.3° C.),with and without the use of Biocide 1; and

FIG. 18 shows the viscosities over time of CO₂ foamed guar-based fluidscontaining Surfactant B at temperatures of about 200° F. (93.3° C.),with and without the use of Biocide 1.

FIG. 19 shows the viscosities over time of CO₂ foamed CMHPG-based fluidscontaining Surfactant A at a temperature of about 200° F. (93.3° C.),with and without the use of Biocide 3 (composed of 25 wt %glutaraldehyde and 75 wt % water).

DETAILED DESCRIPTION

The description and examples are presented solely for the purpose ofillustrating the different embodiments of the invention and should notbe construed as a limitation to the scope and applicability of theinvention. While the compositions of the present invention are describedherein as comprising certain materials, it should be understood that thecomposition could optionally comprise two or more chemically differentmaterials. In addition, the composition can also comprise somecomponents other than the ones already cited. In the summary of theinvention and this detailed description, each numerical value should beread once as modified by the term “about” (unless already expressly somodified), and then read again as not so modified unless otherwiseindicated in context. Also, in the summary of the invention and thisdetailed description, it should be understood that a range, such as aconcentration range, listed or described as being useful, suitable, orthe like, is intended that any and every value within the range,including the end points, is to be considered as having been stated. Forexample, “a range of from 1 to 10” is to be read as indicating each andevery possible number along the continuum between about 1 and about 10.Thus, even if specific data points within the range, or even if no datapoints within the range, are explicitly identified or refer to only afew specific data points, it is to be understood that inventorsappreciate and understand that any and all data points within the rangeare to be considered to have been specified, and that inventors are inpossession of the entire range and all points within the range.

As used herein, the term “liquid phase” is meant to include allcomponents of the fluid except the gas phase. The term “gas” is usedherein to describe any fluid in a gaseous state or in a supercriticalstate, wherein the gaseous state refers to any state for which thetemperature of the fluid is below its critical temperature and thepressure of the fluid is below its vapor pressure, and the supercriticalstate refers to any state for which the temperature of the fluid isabove its critical temperature. As used herein, the terms “energizedfluid” and “fluid” are used interchangeably to describe any stablemixture of gas phase and liquid phase, including foams, notwithstandingthe foam quality value, i.e. the ratio of gas volume to the total volumeof gas and liquid phases.

The invention relates to well treatment energized fluid compositions andmethods related thereto. The fluid typically comprises an aqueousmedium, a viscosifying agent, a surfactant, and a gas component. Thefluid can further contain a suitable crosslinking agent, a gel breaker,an electrolyte, and other desirable additives, as needed. The energizedfluids have adequate rheology for good proppant suspension and transportproperties, and also exhibit excellent stability over a wide range oftemperatures.

Energized fluids are often used in the stimulation of oil and gas wells,and are formed and applied by injecting an aqueous solutionconcomitantly with a gas (most commonly nitrogen, carbon dioxide ortheir mixtures). The dispersion of the gas into the base fluid in theform of bubbles increases the viscosity of such fluid and impactspositively its performance, such as the ability to effectively inducehydraulic fracturing of the formation, and also the capacity to carrysolids, such as proppants. The presence of the gas also enhances theflowback of the fluid. It is commonly known that stable energized fluidsor foams with rheology properties suitable for oilfield operationsbecomes increasingly difficult when the formation temperature is above120° C., or even up to 150° C.

Fluid compositions and methods of the invention are useful in oilfieldoperations, including such operations as fracturing subterraneanformations, modifying the permeability of subterranean formations,fracture or wellbore cleanup, acid fracturing, matrix acidizing, gravelpacking or sand control, and the like. Another application includes theplacement of a chemical plug to isolate zones or to assist an isolatingoperation.

Some surfactants useful for forming the energized fluids useful in theinvention are based upon the following general chemical structure (I):

[R—(OCH₂CH₂)_(m)—O_(q)—YO_(n)]_(p)X  (I)

wherein R is a linear alkyl, branched alkyl, alkyl cycloaliphatic, oralkyl aryl (such as alkyl phenyl) group, which may contain from about 6carbon atoms to about 30 carbons, more particularly from about 10carbons to about 20 carbon atoms (i.e. 11, 12, 13, 14, 15, 16, 17, 18 or19, etc. carbon atoms); O is an oxygen atom; Y is either a sulfur orphosphorus atom; m represents the average number of ethylene oxidegroups and is 1 or more, more particularly m is 1 to about 6; n is aninteger ranging from 1 to 3; p is an integer ranging from 1 to 4; q isan integer ranging from 0 to 1; and X is a cation. The average number ofethylene oxide groups (OCH₂CH₂) can vary. For example, a surfactant thatcontains 3 moles of ethylene oxide, may be a mixture of surfactants with1, 2, 3 and/or 4 ethylene oxide groups. The length of the alkyl groupmay preferably range from about 12 carbon atoms up to about 14 carbonatoms. Any suitable cation, X, may be used, including, but not limitedto, aluminum (Al³⁺), iron (Fe³⁺), titanium (Ti⁴⁺), zirconium (Zr⁴⁺),ammonium (NH₄ ⁺), lithium (Li⁺), magnesium Mg(²⁺), calcium (Ca²⁺),potassium (K⁺), hydrogen (H⁺), sodium (Na⁺), and the like. A mixture ofsurfactants represented by the above structure may also be usedaccording to some embodiments of the invention. One particularly usefulsurfactant is sodium tridecyl ether sulfate, which is represented by thefollowing structure (II):

C₁₃H₂₇(OCH₂CH₂)_(m)—O—SO₃ ⁻Na⁺  (II)

where m ranges from about 1 to about 4. This surfactant is availableunder such trade names as CEDEPAL® TD-403MF-LD, CEDEPAL® TD-403MK-LD,CEDEPAL® TD-407, CEDEPAL® TDS 484, Genapol® XRO, Liposurf EST-30,POLYSTEP® B-40, POLYSTEP® B-41, Rhodapex® EST-30, Rhodapex® EST-30/BLB,Rhodapex® EST-30/SBL, Rhodapex® EST/30-SK, Stanfax 1020, or Sulfochem®TD-3. Another useful surfactant is a mixture of sodium dodecyl ethersulfate (III) and sodium tetradecyl ether sulfate (IV), which arerepresented by the following structures (III) and (IV):

C₁₂H₂₅(OCH₂CH₂)_(m)—O—SO₃ ⁻Na⁺  (III)

C₁₄H₂₉(OCH₂CH₂)_(m)—O—SO₃ ⁻Na⁺  (IV)

In some other embodiments, the alkylene oxide group of the surfactantstructure may be a ethylene oxide, propylene oxide (V), or any mixturethereof (VI and VII given as nonlimiting examples), as represented bythe following:

[R—(OCH₂CH(CH₃))₁—O_(q)—YO_(n)]_(p)X  (V)

[R—(OCH₂CH₂)_(m)(OCH₂CH(CH₃))₁—O_(q)—YO_(n)]_(p)X  (VI)

[R—(OCH₂CH(CH₃))₁(OCH₂CH₂)_(m)—O_(q)—YO_(n)]_(p)X  (VII)

wherein R, O, Y, m, n, p, q and X are the same as defined above; 1represents the average number of propylene oxide groups and ranges from1 or more, more particularly from about 1 to about 6. The ethylene oxideand propylene oxide groups may be in a random or blocked configuration.

Another useful surfactant according to the invention ammoniumnonoxynol-4 sulfate, or ammonium sulfate of nonylphenol ether(4) sulfateas represented by the formula (VIII):

C₉H₁₉—C₆H₄—(C₂H₄O)_(x)—O—SO₃ ⁻.NH₄ ⁺  (VIII)

available under such trade names as Abex® EP-100, Ablusol NP4SF,POLYSTEP® B-1, Rhodapex® CO-436, or Sulfochem® 436, for example. Yetother useful surfactants include other sodium or ammonium alkylarylethoxy sulfates, PEG isodecyl ether phosphate which is available asRhodafac® BG-510, or deceth-4 phosphate which is available as CEDEPHOS®FA600, DePHOS RA-60, DePHOS RA-75, Monafax® 831, Monafax® 1214,Rhodafac® RA-600, or Rhodafac® RA/600-E.

The aqueous medium of fluids useful of the invention may be water orbrine. Where the aqueous medium is a brine, the brine is watercomprising an inorganic salt(s), organic salt(s), or mixture(s) thereof.Preferred inorganic salts include alkali metal halides, more preferablypotassium chloride or ammonium chloride. The carrier brine phase mayalso comprise an organic salt more preferably sodium or potassiumformate, or tetra-methyl ammonium chloride. Preferred inorganic divalentsalts include calcium halides, more preferably calcium chloride orcalcium bromide. Sodium bromide, potassium bromide, or cesium bromidemay also be used.

Fluids useful in the invention include a viscosifying agent that may bea polymer that is either crosslinked or linear, or any combinationthereof. Polymer based viscosifying agents useful in the fluids includenatural polymers, derivatives of natural polymers, synthetic polymers,biopolymers, and the like, or any mixtures thereof. Some nonlimitingexamples of suitable polymers include guar gums, high-molecular weightpolysaccharides composed of mannose and galactose sugars, or guarderivatives such as hydropropyl guar (HPG), carboxymethyl guar (CMG),and carboxymethylhydroxypropyl guar (CMHPG). Cellulose derivatives suchas hydroxyethylcellulose (HEC) or hydroxypropylcellulose (HPC) andcarboxymethylhydroxyethylcellulose (CMHEC) may also be used in eithercrosslinked form, or without crosslinker in linear form. Xanthan,diutan, and scleroglucan, three biopolymers, have been shown to beuseful as viscosifying agents as well. Synthetic polymers, including butnot limited to, polyacrylamide and polyacrylate polymers and copolymers,are used typically for high-temperature applications. Also, associativepolymers for which viscosity properties are enhanced by suitablesurfactants and hydrophobically modified polymers can be used, such ascases where a charged polymer in the presence of a surfactant having acharge that is opposite to that of the charged polymer, the surfactantbeing capable of forming an ion-pair association with the polymerresulting in a hydrophobically modified polymer having a plurality ofhydrophobic groups, as described published U.S. Pat. App. No. US2004/0209780, Harris et. al.

In some method embodiments, the viscosifying agent is awater-dispersible, linear, nonionic, hydroxyalkyl galactomannan polymeror a substituted hydroxyalkyl galactomannan polymer. Examples of usefulhydroxyalkyl galactomannan polymers include, but are not limited to,hydroxy-C₁-C₄-alkyl galactomannans, such as hydroxy-C₁-C₄-alkyl guars.Examples of such hydroxyalkyl guars include hydroxyethyl guar (HE guar),hydroxypropyl guar (HP guar), and hydroxybutyl guar (HB guar), and mixedC₂-C₄, C₂/C₃, C₃/C₄, or C₂/C₄ hydroxyalkyl guars. Hydroxymethyl groupscan also be present in any of these.

As used herein, substituted hydroxyalkyl galactomannan polymers areobtainable as substituted derivatives of the hydroxy-C₁-C₄-alkylgalactomannans, which include: 1) hydrophobically-modified hydroxyalkylgalactomannans, e.g., C₁-C₂₄-alkyl-substituted hydroxyalkylgalactomannans, e.g., wherein the amount of alkyl substituent groups maybe about 2% by weight or less of the hydroxyalkyl galactomannan; and 2)poly(oxyalkylene)-grafted galactomannans (see, e.g., A. Bahamdan & W. H.Daly, in Proc. 8PthP Polymers for Adv. Technol. Int'l Symp. (Budapest,Hungary, September 2005) (PEG- and/or PPG-grafting is illustrated,although applied therein to carboxymethyl guar, rather than directly toa galactomannan)). Poly(oxyalkylene)-grafts thereof can comprise two ormore than two oxyalkylene residues; and the oxyalkylene residues can beC₁-C₄ oxyalkylenes. Mixed-substitution polymers comprising alkylsubstituent groups and poly(oxyalkylene) substituent groups on thehydroxyalkyl galactomannan are also useful herein. In variousembodiments of substituted hydroxyalkyl galactomannans, the ratio ofalkyl and/or poly(oxyalkylene) substituent groups to mannosyl backboneresidues can be about 1:25 or less, i.e. with at least one substituentper hydroxyalkyl galactomannan molecule; the ratio can be: at least orabout 1:2000, 1:500, 1:100, or 1:50; or up to or about 1:50, 1:40, 1:35,or 1:30. Combinations of galactomannan polymers according to the presentdisclosure can also be used.

As used herein, galactomannans comprise a polymannose backbone attachedto galactose branches that are present at an average ratio of from 1:1to 1:5 galactose branches:mannose residues. Galactomannans may comprisea 1→4-linked β-D-mannopyranose backbone that is 1→6-linked toα-D-galactopyranose branches. Galactose branches can comprise from 1 toabout 5 galactosyl residues; in various embodiments, the average branchlength can be from 1 to 2, or from 1 to about 1.5 residues. The branchesmay be monogalactosyl branches. In various embodiments, the ratio ofgalactose branches to backbone mannose residues can be, approximately,from 1:1 to 1:3, from 1:1.5 to 1:2.5, or from 1:1.5 to 1:2, on average.In various embodiments, the galactomannan can have a linear polymannosebackbone. The galactomannan can be natural or synthetic. Naturalgalactomannans useful herein include plant and microbial (e.g., fungal)galactomannans, among which plant galactomannans may be used. In variousembodiments, legume seed galactomannans can be used, examples of whichinclude, but are not limited to: tara gum (e.g., from Cesalpinia spinosaseeds) and guar gum (e.g., from Cyamopsis tetragonoloba seeds). Inaddition, although embodiments of the present invention may be describedor exemplified with reference to guar, such as by reference tohydroxy-C₁-C₄-alkyl guars, such descriptions apply equally to othergalactomannans, as well.

In one embodiment, the polymer is a diutan gum having a tetrasacchariderepeating unit in the polymer backbone as represented by the chemicalformula (IX):

wherein M⁺ is an ionic species, and the weight average molecular weight(Mw) is from about 10⁵ to about 10⁷.

When incorporated, the polymer based viscosifying agent may be presentat any suitable concentration. In various embodiments hereof, thegelling agent can be present in an amount of from about 1 pound (0.4 kg)to less than about 60 pounds (27.2 kg) per thousand gallons (3785liters) of liquid phase, or from about 15 pounds (6.8 kg) to less thanabout 40 pounds (18.1 kg) per thousand gallons (3785 liters), from about15 pounds (6.8 kg) to about 35 pounds (15.9 kg) per thousand gallons(3785 liters), 15 pounds (6.8 kg) to about 25 pounds (11.3 kg) perthousand gallons (3785 liters), or even from about 17 pounds (7.7 kg) toabout 22 pounds (10 kg) per thousand gallons (3785 liters). Generally,the gelling agent can be present in an amount of from about 10 pounds(4.5 kg) to less than about 60 pounds (27.2 kg) per thousand gallons(3785 liters) of liquid phase, with a lower limit of polymer being noless than about 1 pound (0.4 kg), 2 pounds (0.9 kg), 3 pounds (1.4 kg),4 pounds (1.8 kg), 5 pounds (2.3 kg), 6 pounds (2.7 kg), 7 pounds (3.2kg), 8 pounds (3.61 kg), 9 pounds (4.1 kg), 10 pounds (4.5 kg), 11pounds (5.0 kg), 12 pounds (5.4 kg), 13 pounds (5.9 kg), 14 pounds (6.3kg), 15 pounds (6.8 kg), 16 pounds (7.2 kg), 17 pounds (7.7 kg), 18pounds (8.1 kg), or 19 pounds (8.6 kg) per thousand gallons (3785liters) of the liquid phase, and the upper limited being less than about60 pounds (27.2 kg) per thousand gallons (3785 liters), no greater than59 pounds (26.8 kg), 54 pounds (24.5 kg), 49 pounds (22.2 kg), 44 pounds(20.0 kg), 39 pounds (17.7 kg), 34 pounds (15.4 kg), 30 pounds (13.6kg), 29 pounds (13.2 kg), 28 pounds (12.7 kg), 27 pounds (12.3 kg), 26pounds (11.8 kg), 25 pounds (11.4 kg), 24 pounds (10.9 kg), 23 pounds(10.4 kg), 22 pounds (10.0 kg), 21 pounds (9.5 kg), or 20 pounds (9.1kg) per thousand gallons (3785 liters) of the liquid phase. In someembodiments, the polymers can be present in an amount of about 20 pounds(9.1 kg) per thousand gallons (3785 liters). Hydroxypropyl guar,carboxymethyl hydroxypropyl guar, carboxymethyl guar, cationicfunctional guar, guar or mixtures thereof, are particularly usefulpolymers for use herein as a gelling agent. Fluids incorporating polymerbased viscosifying agents preferably have a viscosity value of at leastabout 50 centipoise (50 mPa·s) at a shear rate of about 100 s⁻¹, attreatment temperature. The polymer based viscosifying agent may beintroduced in any practical form, including a slurry, powdered,pre-hydrated, hydrated, and the like.

The gas component of the fluids of the present invention may be producedfrom any suitable gas that forms an energized fluid or foam whenintroduced into the aqueous medium. See, for example, U.S. Pat. No.3,937,283 (Blauer et al.), incorporated herein by reference. The gascomponent may comprise a gas selected from nitrogen, air, argon, carbondioxide, and any mixtures thereof. Particularly useful are the gascomponents of nitrogen or carbon dioxide, in any quality readilyavailable. The gas component may assist in the fracturing and acidizingoperation, as well as the well clean-up process. The fluid may containfrom about 10% to about 90% volume gas component based upon total fluidvolume percent, more particularly from about 20% to about 80% volume gascomponent based upon total fluid volume percent, and more particularlyfrom about 30% to about 70% volume gas component based upon total fluidvolume percent.

In some embodiments, the fluids used may further include a crosslinkerAdding crosslinkers to the fluid may further augment the viscosity ofthe fluid. Crosslinking consists of the attachment of two polymericchains through the chemical association of such chains to a commonelement or chemical group. Suitable crosslinkers may comprise a chemicalcompound containing a polyvalent metal ion such as, but not necessarilylimited to, chromium, iron, boron, aluminum, titanium, antimony andzirconium.

In certain embodiments, the fluids may include a biocide. It has beenfound that inclusion of a biocide can increase the energized fluidviscosity. Examples of suitable biocides include2,2-dibromo-3-nitrilopropionamine and 1,2-benzisothiazolin-3-one. Thebiocide may be used in an amount of from about 0.001% by weight to about1% by weight of the treatment fluid.

The fluids used in some method embodiments of the invention may includean electrolyte which may be an organic acid, organic acid salt, organicsalt, or inorganic salt. Mixtures of the above members are specificallycontemplated as falling within the scope of the invention. This memberwill typically be present in a minor amount (e.g., less than about 30%by weight of the liquid phase).

The organic acid is typically a sulfonic acid or a carboxylic acid, andthe anionic counter-ion of the organic acid salts is typically asulfonate or a carboxylate. Representatives of such organic moleculesinclude various aromatic sulfonates and carboxylates such as p-toluenesulfonate, naphthalene sulfonate, chlorobenzoic acid, salicylic acid,phthalic acid and the like, where such counter-ions are water-soluble.Particularly useful organic acids are formic acid, citric acid,5-hydroxy-1-napthoic acid, 6-hydroxy-1-napthoic acid,7-hydroxy-1-napthoic acid, 1-hydroxy-2-naphthoic acid,3-hydroxy-2-naphthoic acid, 5-hydroxy-2-naphthoic acid,7-hydroxy-2-napthoic acid, 1,3-dihydroxy-2-naphthoic acid, and3,4-dichlorobenzoic acid.

The inorganic salts that are particularly suitable include, but are notlimited to, water-soluble potassium, sodium, and ammonium salts, such aspotassium chloride and ammonium chloride. Additionally, magnesiumchloride, calcium chloride, calcium bromide, zinc halide, sodiumcarbonate, and sodium bicarbonate salts may also be used. Any mixturesof the inorganic salts may be used as well. The inorganic salts may aidin the development of increased viscosity that is characteristic ofpreferred fluids. Further, the inorganic salt may assist in maintainingthe stability of a geologic formation to which the fluid is exposed.Formation stability and in particular clay stability (by inhibitinghydration of the clay) is achieved at a concentration level of a fewpercent by weight and as such the density of fluid is not significantlyaltered by the presence of the inorganic salt unless fluid densitybecomes an important consideration, at which point, heavier inorganicsalts may be used. In some embodiments of the invention, the electrolyteis an organic salt such as tetramethyl ammonium chloride, or inorganicsalt such as potassium chloride. The electrolyte may be used in anamount of from about 0.01 wt % to about 12.0 wt % of the total liquidphase weight, and more particularly from about 0.1 wt % to about 8.0 wt% of the total liquid phase weight.

Fluids used in some embodiments of the invention may also comprise anorganoamino compound. Examples of suitable organoamino compoundsinclude, but are not limited to, tetraethylenepentamine,triethylenetetramine, pentaethylenehexamine, triethanolamine, and thelike, or any mixtures thereof. When organoamino compounds are used influids of the invention, they may be incorporated in an amount fromabout 0.01 wt % to about 2.0 wt % based on total liquid phase weight,more particularly, the organoamino compound may be incorporated at anamount from about 0.05 wt % to about 1.0 wt % based on total liquidphase weight. A particularly useful organoamino compound istetraethylenepentamine, particularly when used with diutan viscosifyingagent at temperatures of approximately 300° F. (150° C.).

Friction reducers may also be incorporated into fluids used in theinvention. Any friction reducer may be used. Also, polymers such aspolyacrylamide, polyisobutyl methacrylate, polymethyl methacrylate andpolyisobutylene as well as water-soluble friction reducers such as guargum, guar gum derivatives, hydrolyzed polyacrylamide, and polyethyleneoxide may be used. Commercial drag reducing chemicals such as those soldby Conoco Inc. under the trademark “CDR” as described in U.S. Pat. No.3,692,676 (Culter et al.) or drag reducers such as those sold byChemlink under the trademarks “FLO 1003, 1004, 1005 & 1008” have alsobeen found to be effective. These polymeric species added as frictionreducers or viscosity index improvers may also act as fluid lossadditives, reducing or even eliminating the need for conventional fluidloss additives.

Breakers, in addition to those described above, may optionally be usedin some methods of the invention. The purpose of this component is to“break” or diminish the viscosity of the fluid so that this fluid ismore easily recovered from the formation during cleanup. With regard tobreaking down viscosity, oxidizers, enzymes, or acids may be used.Breakers reduce the polymer's molecular weight by the action of such anacid, oxidizer, enzyme, or some combination of these on the polymeritself. In the case of borate-crosslinked gels, increasing the pH andtherefore increasing the effective concentration of the activecrosslinker (the borate anion), will allow the polymer to becrosslinked. Lowering the pH will just as easily eliminate theborate/polymer bonds. At pH values at or above 8, the borate ion existsand is available to crosslink and cause gelling. At lower pH values, theborate is tied up by hydrogen and is not available for crosslinking,thus gelation caused by borate ion crosslinking is reversible. Thebreakers may include 0.1 pound (0.05 kg) to 20 pounds (9.1 kg) perthousand gallons (2785 liters) of conventional oxidizers such asammonium persulfates, live or encapsulated, or potassium periodate,calcium peroxide, chlorites, and the like. In oil producing formationsthe film may be at least partially broken when contacted with formationfluids (oil), which may help de-stabilize the film.

A fiber component may be included in the fluids used in the invention toachieve a variety of properties including improving particle suspension,and particle transport capabilities, and gas phase stability. Fibersused may be hydrophilic or hydrophobic in nature, but hydrophilic fibersare particularly useful. Fibers can be any fibrous material, such as,but not limited to, natural organic fibers, comminuted plant materials,synthetic polymer fibers (non-limiting examples including polyester,polyaramide, polyamide, novoloid or a novoloid-type polymer),fibrillated synthetic organic fibers, ceramic fibers, inorganic fibers,metal fibers, metal filaments, carbon fibers, glass fibers, ceramicfibers, natural polymer fibers, and any mixtures thereof. Particularlyuseful fibers are polyester fibers coated to be highly hydrophilic, suchas, but not limited to, DACRON® polyethylene terephthalate (PET) fibersavailable from Invista Corp. Wichita, Kans., USA, 67220. Other examplesof useful fibers include, but are not limited to, polylactic acidpolyester fibers, polyglycolic acid polyester fibers, polyvinyl alcoholfibers, and the like. When used in fluids of the invention, the fibercomponent may be included at concentrations of from about 1 to about 15grams per liter of the liquid phase of the fluid, more particularly, theconcentration of fibers may be from about 2 to about 12 grams per literof liquid, and more particularly, from about 2 to about 10 grams perliter of liquid.

Embodiments of the invention may include other additives and chemicalsthat are known to be commonly used in oilfield applications by thoseskilled in the art. These include, but are not limited to, materials inaddition to those mentioned hereinabove, such as breaker aids, oxygenscavengers, alcohols, scale inhibitors, corrosion inhibitors, fluid-lossadditives, bactericides, iron control agents, organic solvents, and thelike.

Also, the fluids may include a co-surfactant to optimize viscosity or tominimize the formation of stabilized emulsions that contain componentsof crude oil, or as described hereinabove, a polysaccharide orchemically modified polysaccharide, natural polymers and derivatives ofnatural polymers, such as cellulose, derivatized cellulose, guar gum,derivatized guar gum, or biopolymers such as xanthan, diutan, andscleroglucan, synthetic polymers such as polyacrylamides andpolyacrylamide copolymers, oxidizers such as persulfates, peroxides,bromates, chlorates, chlorites, periodates, and the like. Some examplesof organic solvents include ethylene glycol monobutyl ether, isopropylalcohol, methanol, glycerol, ethylene glycol, mineral oil, mineral oilwithout substantial aromatic content, and the like.

Embodiments of the invention may also include placing proppant particlesthat are substantially insoluble in the fluids of the formation.Proppant particles carried by the treatment fluid remain in the fracturecreated, thus propping open the fracture when the fracturing pressure isreleased and the well is put into production. Suitable proppantmaterials include, but are not limited to, sand, nut shells (such aswalnut shells), sintered bauxite, glass beads, ceramic materials,naturally occurring materials, or similar materials. Mixtures ofproppants can be used as well. If sand is used, it will typically befrom about 20 to about 100 U.S. Standard Mesh (approx. 0.84 mm to 0.15mm) in size. Naturally occurring materials may be underived and/orunprocessed naturally occurring materials, as well as materials based onnaturally occurring materials that have been processed and/or derived.Suitable examples of naturally occurring particulate materials for useas proppants include, but are not necessarily limited to: ground orcrushed shells of nuts such as walnut, coconut, pecan, almond, ivorynut, brazil nut, etc.; ground or crushed seed shells (including fruitpits) of seeds of fruits such as plum, olive, peach, cherry, apricot,etc.; ground or crushed seed shells of other plants such as maize (e.g.,corn cobs or corn kernels), etc.; processed wood materials such as thosederived from woods such as oak, hickory, walnut, poplar, mahogany, etc.including such woods that have been processed by grinding, chipping, orother form of particalization, processing, etc. Further information onnuts and composition thereof may be found in Encyclopedia of ChemicalTechnology, Edited by Raymond E. Kirk and Donald F. Othmer, ThirdEdition, John Wiley & Sons, Volume 16, pages 248-273 (entitled “Nuts”),Copyright 1981, which is incorporated herein by reference.

The concentration of proppant in the fluid can be any concentrationknown in the art, and, as an example, may be in the range of from about0.05 kilogram to about 3 kilograms of proppant added per liter of liquidphase. Also, any of the proppant particles can further be coated with aresin to potentially improve the strength, clustering ability, and flowback properties of the proppant.

Conventional propped hydraulic fracturing techniques, with appropriateadjustments if necessary, as will be apparent to those skilled in theart, are used in the methods of the invention. In an example of afracture stimulation treatment, according to the present invention, thetreatment may begin with a conventional pad stage to generate thefracture, followed by a sequence of stages in which a viscous carrierfluid transports proppant into the fracture as the fracture ispropagated. Typically, in this sequence of stages the amount of proppingagent is increased, normally stepwise. The pad and carrier fluid can be,and usually are, a gelled aqueous fluid, such as water or brinethickened with a viscoelastic surfactant or with a water soluble ordispersible polymer such as guar, hydroxypropylguar or the like. The padand carrier fluids may contain various additives. Non-limiting examplesare fluid loss additives, crosslinking agents, clay control agents,breakers, iron control agents, and the like, provided that the additivesdo not affect the stability or action of the fluid.

The procedural techniques for pumping fracture stimulation fluids down awellbore to fracture a subterranean formation are well known. The personthat designs such fracturing treatments is the person of ordinary skillto whom this disclosure is directed. That person has available manyuseful tools to help design and implement the fracturing treatments, oneof which is a computer program commonly referred to as a fracturesimulation model (also known as fracture models, fracture simulators,and fracture placement models). Most, if not all, commercial servicecompanies that provide fracturing services to the oilfield have one ormore fracture simulation models that their treatment designers use. Onecommercial fracture simulation model that is widely used by severalservice companies is known as FracCADE™. This commercial computerprogram is a fracture design, prediction, and treatment-monitoringprogram designed by Schlumberger, Ltd. All of the various fracturesimulation models use information available to the treatment designerconcerning the formation to be treated and the various treatment fluids(and additives) in the calculations, and the program output is a pumpingschedule that is used to pump the fracture stimulation fluids into thewellbore. The text “Reservoir Stimulation,” Third Edition, Edited byMichael J. Economides and Kenneth G. Nolte, Published by John Wiley &Sons, (2000), is an excellent reference book for fracturing and otherwell treatments; it discusses fracture simulation models in Chapter 5(page 5-28) and the Appendix for Chapter 5 (page A-15)), which areincorporated herein by reference.

In the fracturing treatment, fluids of the invention may be used in thepad treatment, the proppant stage, or both. The components of the liquidphase may be mixed on the surface. Alternatively, a the fluid may beprepared on the surface and pumped down tubing while the gas componentcould be pumped down the annular to mix down hole, or vice versa.

Yet another embodiment of the invention includes the use fluids based onthe invention for cleanup. The term “cleanup” or “fracture cleanup”refers to the process of removing the fracture fluid (without theproppant) from the fracture and wellbore after the fracturing processhas been completed. Techniques for promoting fracture cleanuptraditionally involve reducing the viscosity of the fracture fluid asmuch as practical so that it will more readily flow back toward thewellbore. While breakers are typically used in cleanup as energizedfluids, the fluids of the invention may effective for use in cleanupoperations, with or without a breaker.

In another embodiment, the present invention relates to use of fluidsbased on the invention for gravel packing a wellbore. As a gravelpacking fluid, it preferably comprises gravel or sand and other optionaladditives such as filter cake clean up reagents such as chelating agentsreferred to above or acids (e.g. hydrochloric, hydrofluoric, formic,acetic, citric acid) corrosion inhibitors, scale inhibitors, biocides,leak-off control agents, among others. For this application, suitablegravel or sand is typically having a mesh size between 8 and 70 U.S.Standard Sieve Series mesh (2.38 mm-0.21 mm).

The following examples are presented to illustrate the preparation andproperties of energized aqueous fluids comprising heteropolysaccharidesand a surfactant, and should not be construed to limit the scope of theinvention, unless otherwise expressly indicated in the appended claims.All percentages, concentrations, ratios, parts, etc. are by weightunless otherwise noted or apparent from the context of their use.

The following examples serve to further illustrate the invention.

EXAMPLES

In the examples, the following surfactants composition were evaluated:

-   -   Surfactant A: 30 wt % sodium tridecyl ether sulfate, 7.9 wt %        isopropanol, 62.1 wt % water, available as RHODAPEX® EST-30/I        from Rhodia, Inc. Cranbury, N.J.    -   Surfactant B: 50 wt % ammonium C6-C10 alcohol ethoxysulfate,        13.2 wt % ethanol, 12 wt % propylene glycol, 0.8 wt % C6-C10        ethoxylated alcohol, 25 wt % water.    -   Surfactant C: 30 wt % amphoteric alkyl amine, 10 wt %        isopropanol, 60 wt % water.    -   Surfactant D: 30 wt % sodium lauryl sulfate, 70 wt % water.

Surfactant A is one example of a surfactant useful in the invention. Thebenefits of this surfactant are illustrated through the examplesdescribed below. Surfactants B, C and D were the foaming agents used forcomparison purposes. Surfactant B, is a C₆-C₁₀ alcohol ethoxysulfate,and is a common surfactant which is widely used for both N₂ and CO₂foamed fluids. It can provide good foam stability up to 120° C. in N₂foams with gelling agents such as guar. For CO₂ foams at temperaturessuch as 95° C. to 120° C., Surfactant C, an amphoteric alkyl amine, isoften used to provide relatively stable foams. Surfactant D is a C₁₂sulfate surfactant.

All the foamed fluid viscosity measurements were performed on a fullyautomated high-pressure-high-temperature capillary rheometer, aChandler-Schlumberger Foam Rheometer System. Details of the operation ofthis equipment are reported in Hutchins, R. D. and Miller, M. J., ACirculating Foam Loop for Evaluating Foam at Conditions of Use, SPEpaper 80242. SPE International Symposium on Oilfield Chemistry. Houston,USA 5-7 Feb. 2003. The gas/liquid composition of the energized fluid wasverified through the measured density.

Example 1

Guar-based fluids energized with N₂ were tested using Surfactants A andB at approximately 120° C. These energized fluids contained 0.6 wt %guar, 1.0 vol % surfactant A or B, and 0.1 wt % tetramethyl ammoniumchloride, in aqueous solutions. Guar was added in a slurry form in whichguar and diesel solvent each accounted for 50 wt % of the slurry. Foamquality was 70%, and the temperature was constant at about 120° C. Theviscosity was measured at 100 s⁻¹. The results are shown in FIG. 1, andindicate that Surfactant A provides better foam stability compared withSurfactant B at 120° C. in N₂ foams. The sample using Surfactant Acontained less active surfactant as compared with Surfactant B (30 wt %vs. 50 wt %) but the viscosity was approximately 35% greater for thatfor the sample using Surfactant B.

Example 2

Guar-based fluids foamed with CO₂ were tested using Surfactants A and Cat approximately 120° C. The fluids contained 0.6 wt % guar, 1.0 vol %Surfactant A or C, and 0.1 wt % tetramethyl ammonium chloride. Theresults are presented in FIG. 2. FIG. 2 shows that Surfactant A providessignificantly better foam stability compared with Surfactant C at 120°C. in CO₂ foams. It can be seen that the foam viscosity measured at 100s⁻¹ by using Surfactant C fell below 50 mPa·s after 75 min. It iscommonly accepted that 50 mPa·s is the minimum viscosity for fracturingapplications. With Surfactant A, much greater viscosity was achievedeven after 2 hours. Foam quality was 70%, and the temperature wasconstant at about 120° C.

Example 3

A guar-based fluid foamed with N₂ was tested using Surfactant D atapproximately 120° C. The fluid contained 0.36 wt % guar, 1.0 vol %Surfactant D, and 0.1 wt % tetramethyl ammonium chloride. Guar was addedin a slurry form in which guar and mineral oil each accounted for 50 wt% of the slurry. Foam quality was approximately 70% at time 0 min. Thedensity and shear rate fluctuated as a result of the instable foam. Theresults are presented in FIG. 3. FIG. 3 illustrates that Surfactant D, aC₁₂ sulfate, was unable to create a stable foam at 120° C. in N₂ foams,and may suggest that the ethylene oxide units in Surfactant A may playan important role in providing greater foam stability. At the same gelloading, Surfactant A maintained the foam viscosity above 50 mPa·s at100 s⁻¹ for over 2 hours (see in FIG. 8).

Example 4

A guar-based fluid foamed with CO₂ containing Surfactant A was tested ata temperature of about 135° C. The fluid contained 0.36 wt % guar, 1.5vol % Surfactant A, and 0.1 wt % tetramethyl ammonium chloride. Guar wasadded in a slurry form in which guar and mineral oil each accounted for50 wt % of the slurry. Foam quality was 70%. The results are presentedin FIG. 4. As can be seen from FIG. 4, Surfactant A can extend thetemperature limit of conventional guar-based fluids from 120° C. to 135°C. in CO₂ foams. The viscosity of the foamed fluid was stable withvalues above 50 mPa·s at 100 s⁻¹. It was also noted that the fluidstability was maintained at 135° C. without any temperature stabilizer,which is commonly required at elevated temperatures, i.e., temperaturesabove 93° C. The surfactant thus extended the temperature limit of thefoam.

Example 5

A diutan-based fluid foamed with CO₂ containing Surfactant A was testedat a temperature of about 150° C. The energized fluid contained 0.36 wt% diutan gum, 1.5 vol % Surfactant A, 7 wt % potassium chloride, and 0.5vol % tetraethylene pentamine. Diutan was added in a slurry form thatcomprised 38 wt % diutan, 61 wt % 2-butoxyethanol, and 1% suspensionagent. The foam quality was 71%, and the temperature was constant atabout 150° C. The results are presented in FIG. 5. FIG. 5 demonstratesthat Surfactant A is able to provide a stable CO₂ foam at temperaturesas high as about 150° C. A temperature stabilizer,tetraethylenepentamine, was added to the fluid to prevent the polymerfrom degrading at high temperatures.

Example 6

Surfactant A was evaluated with carboxymethyl hydroxypropyl guar (CMHPG)based fluids at high temperatures. CMHPG-based fluids foamed with CO₂and N₂ containing Surfactant A were tested at a temperatures of about120° C. The gelling agent was CMHPG added at 0.60 wt %, 1.5 vol %surfactant A, and 0.1 wt % tetramethyl ammonium chloride. CMHPG wasadded in a slurry form in which the polymer and mineral oil eachaccounted for approximately 50 wt % of the slurry. The foam quality was70%. The results are presented in FIG. 6. FIG. 6 shows that Surfactant Acan provide viscosities greater than 50 mPa·s at 100 s⁻¹ at 120° C. ineither CO₂ or N₂ foams. It should be noted that the fluid did notcontain any temperature stabilizer, which is commonly required at thistemperature for guar or CMHPG based fluids.

Example 7

In addition to its excellent performance at high temperatures,Surfactant A also functioned as a good foaming agent at temperatureslower than 120° C. Surfactant A was used in guar-based fluids foamedwith N₂ at 100° F. (38° C.) and 150° F. (66° C.). The fluids contained0.24 wt % guar, 0.5 vol % Surfactant A, and 0.1 wt % tetramethylammonium chloride. The foam quality was 70% and the temperature wasconstant at either 100° F. (38° C.) or 150° F. (66° C.). The results areseen in FIG. 7. The guar polymer used was delivered in the form of anenvironmentally friendly or “green” slurry in which the polymer andmineral oil each accounted for approximately 50 wt % of the slurry.

Example 8

Surfactant A was used in guar-based fluids foamed with N₂ at 200° F.(93.3° C.) and 250° F. (121° C.). The fluids contained 0.36 wt % guar,1.0 vol % Surfactant A, and 0.1 wt % tetramethyl ammonium chloride. Thefoam quality was 70% and the temperature was constant at either 200° F.(93.3° C.) or 250° F. (121° C.). The results are seen in FIG. 8. Theguar polymer was added as a slurry in mineral oil in which the polymerand mineral oil each accounted for approximately 50 wt % of the slurry.

Example 9

Surfactant A was used in guar-based fluids foamed with CO₂ at 100° F.(38° C.) and 150° F. (66° C.). The fluids contained 0.24 wt % guar, 0.5vol % Surfactant A, and 0.1 wt % tetramethyl ammonium chloride. The foamquality was 67% at 100° F. (38° C.) and 70% at 150°F. (66° C.). Theresults are seen in FIG. 9. The guar polymer was added as a slurry inmineral oil in which the polymer and mineral oil each accounted forapproximately 50 wt % of the slurry.

Example 10

Surfactant A was used in guar-based fluids foamed with CO₂ at 200° F.(93.3° C.) and 250° F. (121° C.). The fluids contained 0.36 wt % guar,1.0 vol % Surfactant A, and 0.1 wt % tetramethyl ammonium chloride. Thefoam quality was 70% and the temperature was constant at either 200° F.(93.3° C.) or 250° F. (121° C.). The results are seen in FIG. 10. Theguar polymer was added as a slurry in mineral oil in which the polymerand mineral oil each accounted for approximately 50 wt % of the slurry.

As can be seen from Examples 7 through 10, foam viscosities of muchgreater than 50 mPa·s at 100 s⁻¹ can be obtained with guar-based fluidscontaining Surfactant A over a range of temperatures, regardless of thegas type used.

Example 11

Surfactant A was used in CMHPG-based fluids foamed with N₂ at 100° F.(38° C.), 150° F. (66° C.) and 200° F. (93.3° C.). The fluids contained0.36 wt % CMHPG, 1.0 vol % Surfactant A, and 0.1 wt % tetramethylammonium chloride. The foam quality was 70% and the temperature wasconstant at either 100° F. (38° C.), 150° F. (66° C.) or 200° F. (93.3°C.). The results are seen in FIG. 11. The CMHPG polymer used wasdelivered in the form of a “green” slurry in which the polymer andmineral oil each accounted for approximately 50 wt % of the slurry.

Example 12

Surfactant A was used in CMHPG-based fluids foamed with CO₂ at 150° F.(66° C.) and 200° F. (93.3° C.). The fluids contained 0.36 wt % CMHPG,1.0 vol % Surfactant A, and 0.1 wt % tetramethyl ammonium chloride. Thefoam quality was 70% and the temperature was constant at either 150° F.(66° C.) or 200° F. (93.3° C.). The results are seen in FIG. 12. TheCMHPG polymer used in these experiments was delivered in the form of a“green” slurry in which the polymer and mineral oil each accounted forapproximately 50 wt % of the slurry.

As can be seen from Examples 11 and 12, in addition to its good foamingproperties in guar-based fluids, Surfactant A can also generate stablefoams in CMHPG-based fluids at various temperatures.

Example 13

It was discovered that energized fluid viscosity of a CMHPG-based fluidmay increased with a small amount of a biocide. Surfactant A was used inCMHPG-based fluids foamed with N₂ at 200° F. (93.3° C.). The fluidscontained 0.36 wt % CMHPG, 1.0 vol % Surfactant A, and 0.1 wt %tetramethyl ammonium chloride. The foam quality was 70%. and thetemperature was constant at around 200° F. (93.3° C.). The CMHPG polymerused in these experiments was delivered in the form of a “green” slurryin which the polymer and mineral oil each accounted for approximately 50wt % of the slurry. In one fluid sample, no biocide was used. In theother sample, a biocide was used in which the biocide contained 9 wt %1,2-benzisothiazolin-3-one and 3.5 wt % sodium hydroxide, 43 wt %propane-1,2-diol, in an aqueous solution, all based upon total weight ofthe biocide solution. The results are presented in FIG. 13.

Example 14

Surfactant A was used in CMHPG-based fluids foamed with CO₂ at 200° F.(93.3° C.). The fluids contained 0.36 wt % CMHPG, 1.0 vol % SurfactantA, and 0.1 wt % tetramethyl ammonium chloride. The foam quality was 70%.and the temperature was constant at around 200° F. (93.3° C.). The CMHPGpolymer used in these experiments was delivered in the form of a “green”slurry in which the polymer and mineral oil each accounted forapproximately 50 wt % of the slurry. In one fluid sample no biocide wasused. In the other sample, a biocide was used in which the biocidecontained 9 wt % 1,2-benzisothiazolin-3-one and 3.5 wt % sodiumhydroxide, 43 wt % propane-1,2-diol, in an aqueous solution, all basedupon total weight of the biocide solution. The results are presented inFIG. 14.

Example 15

Different biocides were used with Surfactant A. The biocides used wereas follows:

-   -   Biocide 1: 42.5 wt % propane-1,2-diol, 2 to 5 wt % sodium        hydroxide, 9 wt % 1,2-benziisothiazolin-3-one, and 43.5 to 46.5        wt % water.    -   Biocide 2: 1 to 5 wt % 2-bromo-3-nitrilopropionamide and 60 to        100 wt % 2,2-dibromo-3-nitrilopropionamine.        Viscosified fluids with and without Biocides 1 and 2 were        prepared using a CO₂ foamed fluid containing 0.36 wt % CMHPG,        1.0 vol % Surfactant A and 0.1 wt % tetramethyl ammonium        chloride. The foam quality was 70% and the temperature was        constant at about 200° F. (93.3. ° C.). The results are        presented in FIG. 15.

Example 16

It was found that the viscosity enhancements induced by biocides may beunique to the particular surfactant used. Viscosified fluids with andwithout Biocide 1 were prepared using a CO₂ foamed fluid containing 0.36wt % CMHPG, 1.0 vol % Surfactant B and 0.1 wt % tetramethyl ammoniumchloride. The foam quality was 70% and the temperature was constant atabout 200° F. (93.3. ° C.). The results are presented in FIG. 16. As canbe seen from FIG. 16, there was little viscosity change when Biocide 1was used in combination with the fluid containing Surfactant B.

Example 17

When biocides are used, the type of polymer used may also have aneffect. Viscosified fluids with and without Biocide 1 were preparedusing a CO₂ foamed fluids containing 0.36 wt % guar and 0.1 wt %tetramethyl ammonium chloride. Surfactants A and B were used in each ofthese fluids in an amount of 1.0 vol %. The foam quality for the fluidswas 70% and the temperature was constant at about 200° F. (93.3. ° C.).The results of those fluids employing Surfactant A are presented in FIG.17. The results of those fluids employing Surfactant B are presented inFIG. 18. As can be seen from FIGS. 17 and 18, there was no viscosityincrease when guar was used in combination with the fluids containingeither Surfactant A or B. This may be due to the fact that guar isnon-ionic, whereas CMHPG is anionic and may interact with the biocide toincrease its viscosity.

Example 18

A glutaraldehyde biocide (Biocide 3) was used in combination withSurfactant A. Biocide 3 contained 25 wt % glutaraldehyde and 75 wt %water. Viscosified fluids with 0.2 vol. % Biocide 3 and without Biocide3 were prepared using a CO₂ foamed fluids containing 0.36 wt % CMHPG and0.1 wt % tetramethyl ammonium chloride. Surfactant A was used in each ofthese fluids in an amount of 1.0 vol %. The foam quality for the fluidswas 70% and the temperature was constant at about 200° F. (93.3. ° C.).The results are presented in FIG. 19. As can be seen from FIG. 19, therewas no viscosity increase when Biocide 3 was used in combination withSurfactant A.

Example 19

Field tests were conducted wherein ten fracturing treatments wereperformed using Surfactant A as the foaming agent under variousconditions. The reservoir bottom hole static temperatures ranged from160° F. (71° C.) to 200° F. (93° C.). The gas phase of the foamed fluidswas carbon dioxide and the base fluids included non-crosslinked guarfluid, boron crosslinked guar gel and titanium crosslinked guar fluid.All ten treatments were pumped as designed and showed that Surfactant Awas an effective foaming agent for fracturing fluids.

Although the methods have been described herein for, and are mosttypically used for, hydrocarbon production, they may also be used ininjection wells and for production of other fluids, such as water orbrine. The particular embodiments disclosed above are illustrative only,as the invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details herein shown, other than as described in theclaims below. It is therefore evident that the particular embodimentsdisclosed above may be altered or modified and all such variations areconsidered within the scope and spirit of the invention. Accordingly,the protection sought herein is as set forth in the claims below.

1-26. (canceled)
 27. A wellbore treatment fluid comprising an aqueousmedium, a gas component, a viscosifying agent, an alcohol, and asurfactant, wherein the surfactant is represented by the chemicalformula:[R—(OCH₂CH₂)_(m)—O_(q)—YO_(n)]_(p)X wherein R is a linear alkyl,branched alkyl, alkyl cycloaliphatic, or alkyl aryl group; O is anoxygen atom; Y is either a sulfur or phosphorus atom; m is 1 or more; nis an integer ranging from 1 to 3; p is an integer ranging from 1 to 4;q is an integer ranging from 0 to 1; and X is a cation.
 28. The fluid ofclaim 27, wherein the alcohol is isopropyl alcohol.
 29. The fluid ofclaim 27, wherein R is a linear alkyl, branched alkyl, alkylcycloaliphatic, or alkyl aryl group containing from about 10 to about 20carbon atoms.
 30. The fluid of claim 27, wherein m is an integer rangingfrom 1 to about
 6. 31. The fluid according to claim 27, wherein thesurfactant comprises sodium tridecyl ether sulfate, as represented bythe following structure:C₁₃H₂₇(OCH₂CH₂)_(m)—O—SO₃ ⁻Na⁺ wherein m ranges from 1 to about
 6. 32.The fluid according to claim 27, wherein the surfactant is comprised ofa mixture of sodium dodecyl ether sulfate and sodium tetradecyl ethersulfate, as represented by the following structures:C₁₂H₂₅(OCH₂CH₂)_(m)—O—SO₃ ⁻Na⁺C₁₄H₂₉(OCH₂CH₂)_(m)—O—SO₃ ⁻Na⁺ wherein m ranges from 1 to about
 6. 33.The fluid according to claim 27, wherein the viscosifying agent isselected from guar or a guar derivative, hydroxypropylguar,carboxymethyl guar, carboxymethylhydroxypropyl guar, cationic guar orhydrophobically modified guar or a combination of these.
 34. The fluidaccording to claim 27, wherein the viscosifying agent is diutan gumhaving a tetrasaccharide repeating unit in the polymer backbone asrepresented by the chemical formula:

wherein M⁺ is an ionic species, and wherein the weight average molecularweight (Mw) is from about 10⁵ to about 10⁷.
 35. The fluid according toclaim 27, wherein the viscosifying agent is selected from the groupconsisting of natural polymers, derivatives of natural polymers,synthetic polymers, associative polymers, and biopolymers.
 36. The fluidaccording to claim 27, wherein the surfactant is incorporated in anamount of from about 0.02 wt % to about 5 wt % of total liquid phaseweight.
 37. The fluid according to claim 27, wherein the fluid furthercomprises an electrolyte selected from the group consisting of organicacids, organic acid salts, inorganic salts, and combinations of one ormore organic acids or organic acid salts with one or more inorganicsalts, and the electrolyte is incorporated in an amount of from about0.01 wt % to about 12.0 wt % of the total liquid phase weight.
 38. Thefluid according to claim 27, wherein the gas component comprises a gasselected from the group consisting of nitrogen, carbon dioxide, air andany mixtures thereof.
 39. The fluid according to claim 27, wherein saidgas component comprises from about 10% to about 90% of total fluidvolume percent.
 40. The fluid according to claim 27, further comprisinga proppant.
 41. The fluid according to claim 40, wherein the proppant isselected from the group consisting of sand, nut shells, sinteredbauxite, glass beads, ceramic materials, resin coated proppant,naturally occurring materials, or any mixtures thereof.
 42. The fluidaccording to claim 27, further comprising a crosslinker containing ametal ion selected from the group consisting of chromium, iron, boron,titanium, and zirconium.
 43. The fluid according to claim 27, furthercomprising a breaker.
 44. The fluid according to claim 27, furthercomprising a temperature stabilizer.
 45. The fluid according to claim27, further comprising an organoamino compound selected from the groupconsisting of tetraethylenepentamine, triethylenetetramine,pentaethylenehexamine, triethanolamine, and any mixtures thereof, andthe organoamino compound is incorporated in an amount from about 0.01 wt% to about 2.0 wt % based on total liquid phase weight.
 46. The fluidaccording to claim 27, further comprising a fiber component.